This section introduces various aspects of art that may be associated with some embodiments of the present invention to facilitate a better framework for understanding some of the various techniques and applications of the claimed subject matter. Accordingly, it should be understood that these Background section statements are to be read in this light and not necessarily as admissions of prior art.
Drill tool assembly vibrations are known to potentially have a significant effect on Rate of Penetration (ROP) and represent a significant challenge to interpret and mitigate in pursuit of reducing the time and cost of drilling subterranean wells. Drill tool assemblies vibrate during drilling for various reasons related to one or more drilling parameters. For example, the rotary speed (often expressed in revolutions per minute, or RPM), weight on bit (WOB), mud viscosity, etc. each may affect the vibrational tendency of a given drill tool assembly during a drilling operation. Measured depth (MD), rock properties, hole conditions, and configuration of the drill tool assembly may also influence drilling vibrations. As used herein, drilling parameters include characteristics and/or features of both the drilling hardware (e.g., drill tool assembly) and the drilling operations.
As used herein, drill tool assembly refers to assemblies of components used in drilling operations. Exemplary components that may collectively or individually be considered a drill tool assembly include rock cutting devices, bits, mills, reamers, bottom hole assemblies, drill collars, drill strings, couplings, subs, stabilizers, MWD tools, motors, etc. Exemplary rig systems may include the top drive, rig control systems, etc., and may form certain boundary conditions. Deployment of vibrationally poor drill tool assembly designs and conducting drilling operations at conditions of high downhole vibrations can result in loss of rate of penetration, shortened drill tool assembly life, increased number of trips, increased failure rate of downhole tools, and increased non-productive time. It is desirable to provide the drilling engineer and/or rig operating personnel with a useful but not overly complex tool utilizing readily available data and quickly estimating the vibrational tendencies of the drill tool assembly.
A fixed cutter bit often requires more torque than a corresponding roller cone bit drilling similar formations at comparable conditions, although both bits can experience torque issues. Increased bit torque can lead to an increase in the phenomenon known as “stick-slip,” an unsteady rotary speed at the bit, even when surface rotary speed remains substantially constant. Excessive stick-slip can be severely damaging to drill string assemblies. Roller cone bits may sometimes be more prone to axial vibration issues than corresponding fixed cutter bits. Although axial vibrations may be reduced by substituting fixed cutter bits for roller cone bits, some drilling operations with either type of bit may continue to experience axial vibration problems. Fixed cutter bits can be severely damaged by axial vibrations as the PDC wafer can be knocked off its substrate if the axial vibrations are severe. Axial vibrations are known to be problematic for rotary tricone bits, as the classic trilobed bottomhole pattern generates axial motion at the bit. There are known complex mathematical and operational methods for measuring and analyzing downhole vibrations. However, these typically require a substantial amount of data, strong computational power, and special skill to use and interpret.
Typically, severe axial vibration dysfunction can be manifested as “bit bounce,” which can result in a momentary lessening or even a momentary complete loss of contact between the rock formation and the drill bit cutting surface through part of the vibration cycle. Such axial vibrations can cause dislocation of PDC cutters and tricone bits may be damaged by high shock impact with the formation. Dysfunctional axial vibration can occur at other locations in the drill tool assembly. Other cutting elements in the drill tool assembly could also experience a similar effect. Small oscillations in weight on bit (WOB) can result in drilling inefficiencies, leading to decreased ROP. For example, the depth of cut (DOC) of the bit typically varies with varying WOB, giving rise to fluctuations in the bit torque, thereby inducing torsional vibrations. The resulting coupled torsional-axial vibrations may be among the most damaging vibration patterns as this extreme motion may then lead to the generation of lateral vibrations.
Recently developed practices around optimizing the Bottom-Hole Assembly (BHA) design (WO 2008/097303) and drilling parameters for robust vibrational performance, and using real-time Mechanical Specific Energy (MSE) monitoring for surveillance of drilling efficiency (US 2009/0250264) have significantly improved drilling performance. MSE is particularly useful in identifying drilling inefficiencies arising from, for example, dull bits, poor weight transfer to the bit, and whirl. These dysfunctions tend to reduce ROP and increase expended mechanical power due to the parasitic torques generated, thereby increasing MSE. The availability of real-time MSE monitoring for surveillance allows the driller to take corrective action. One of the big advantages of MSE analysis is that it does not require real-time downhole tools that directly measure vibration severity, which are expensive and prone to malfunction in challenging drilling environments. Unfortunately, MSE analysis may not provide reliable information about the severity of torsional or axial oscillations. Field data shows intervals for which MSE does detect such patterns and other instances for which there is no vibration signature in the MSE data. Therefore, it is desirable to have additional indicators complementary to MSE that can provide torsional and/or axial severity from surface data, thereby avoiding the costly step of deploying downhole tools just for this purpose.
Multiple efforts have been made to study and/or model these more complex torsional and axial vibrations, some of which are discussed here to help illustrate the advances made by the technologies of the present disclosure. DEA Project 29 was a multi-partner joint industry program initiated to develop modeling tools for analyzing drill tool assembly vibrations. The program focused on the development of an impedance-based, frequency-dependent, mass-spring-dashpot model using a transfer function methodology for modeling axial and torsional vibrations. These transfer functions describe the ratio of the surface state to the input condition at the bit. The boundary conditions for axial vibrations consisted of a spring, a damper at the top of the drill tool assembly (to represent the rig) and a “simple” axial excitation at the bit (either a force or displacement). For torsional vibrations, the bit was modeled as a free end (no stiffness between the bit and the rock) with damping. This work also indicated that downhole phenomena such as bit bounce and stick-slip are observable from the surface. While the DEA Project 29 recognized that the downhole phenomena were observable from the surface, they did not specifically attempt to quantify this. Results of this effort were published as “Coupled Axial, Bending and Torsional Vibration of Rotating Drill Strings”, DEA Project 29, Phase III Report, J. K. Vandiver, Massachusetts Institute of Technology and “The Effect of Surface and Downhole Boundary Conditions on the Vibration of Drill strings,” F. Clayer et al, SPE 20447, 1990.
Additionally, U.S. Pat. No. 5,852,235 ('235 patent) and U.S. Pat. No. 6,363,780 ('780 patent) describe methods and systems for computing the behavior of a drill bit fastened to the end of a drill string. In '235, a method was proposed for estimating the instantaneous rotational speed of the bit at the well bottom in real-time, taking into account the measurements performed at the top of the drill string and a reduced model. In '780, a method was proposed for computing “Rf, a function of a principal oscillation frequency of a weight on hook WOH divided by an average instantaneous rotating speed at the surface of the drillstring, Rwob being a function of a standard deviation of a signal representing a weight on bit WOB estimated by the reduced physical model of the drill string from the measurement of the signal representing the weight on hook WOH, divided by an average weight on bit WOB0 defined from a weight of the drill string and an average of the weight on hook WOH, and any dangerous longitudinal behavior of the drill bit determined from the values of Rf and Rwob” in real-time.
These methods require being able to run in real-time and a “reduced” model that can accept a subset of measurements as input and generate outputs that closely match the remaining measurements. For example, in '235 the reduced model may accept the surface rotary speed signal as an input and compute the downhole rotary speed and surface torque as outputs. However, the estimates for quantities of interest, such as downhole rotary speed, cannot be trusted except for those occurrences that obtain a close match between the computed and measured surface torque. This typically requires continuously tuning model parameters, since the torque measured at the surface may change not only due to torsional vibrations but also due to changes in rock formations, bit characteristics, borehole patterns, etc., which are not captured by the reduced model. Since the reduced model attempts to match the dynamics associated with relevant vibrational modes as well as the overall trend of the measured signal due to such additional effects, the tuned parameters of the model may drift away from values actually representing the vibrational state of the drilling assembly. This drift can result in inaccurate estimates of desired parameters.
Another disadvantage of such methods is the requirement for specialized software, trained personnel, and computational capabilities available at each drilling operation to usefully utilize and understand such systems.
A recent patent application publication entitled “Method and Apparatus for Estimating the Instantaneous Rotational Speed of a Bottom Hole Assembly,” (WO 2010/064031) continues prior work in this area as an extension of IADC/SPE Publication 18049, “Torque Feedback Used to Cure Slip-Stick Motion,” and previous related work. One primary motivation for these efforts is to provide a control signal to the drilling apparatus to adjust the power to the rotary drive system to reduce torsional drill string vibrations. A simple drill string compliance function is disclosed providing a stiffness element between the rotary drive system at the surface and the bottom hole assembly. Inertia, friction, damping, and several wellbore parameters are excluded from the drill string model. Also, the '031 reference fails to propose means to evaluate the quality of the torsional vibration estimate by comparison with downhole data, offers only simple means to calculate the downhole torsional vibrations using a basic torsional spring model, provides few means to evaluate the surface measurements, does not discuss monitoring surface measurements for bit axial vibration detection, and does not use the monitoring results to make a comprehensive assessment of the amount or severity of stick-slip observed for a selected drilling interval. This reference merely teaches a basic estimate of the downhole instantaneous rotational speed of the bit for the purpose of providing an input to a surface drive control system. Such methods fail to enable real-time diagnostic evaluation and indication of downhole dysfunction.
Other related material may be found in “Development of a Surface Drillstring Vibration Measurement System”, A. A. Besaisow, et al., SPE 14327, 1985; “Surface Detection of Vibrations and Drilling Optimization: Field Experience”, H. Henneuse, SPE 23888, 1992; and, “Application of High Sampling Rate Downhole Measurements for Analysis and Cure of Stick-Slip in Drilling,” D. R. Pavone and J. P. Desplans, 1994, SPE 28324. Additionally, patent application WO 2009/155062 A1, “Methods and Systems for Mitigating Drilling Vibrations,” provides further details on the methods presented herein. Numerous theoretical and analytical methods have been taught and disclosed in the art, but few have also provided methods for applying such technology. The art remains in need of a more reliable method for predicting downhole vibrational effects utilizing information that can be relatively easily obtained from surface measurements and data. The art particularly also remains in need of such methods that can be usefully employed at remote locations such as at a drill site, without the need for exceptional engineering and computational skills and equipment.